Good afternoon and welcome to the Aemetis Third Quarter 2023 Earnings Review Conference Call. At this time, all participants are in a listen-only mode and a brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Todd Waltz, Executive Vice President and Chief Financial Officer of Aemetis, Incorporated. Mr. Waltz, you may begin.

Thank you, Ali. Welcome to Aemetis' third quarter 2023 earnings review conference call. Joining us for the call today is Eric McAfee, Founder, Chairman, and CEO of Aemetis. We suggest reading our website at aemetis.com to review today's earnings press release, the Aemetis Corporate and Investor Presentations, filings with the Securities and Exchange Commission, recent press releases, and previous earnings conference calls. The presentation for today's call is available for review or download on the Investors section of aemetis.com website. Before we begin our discussion today, I'd like to read the following disclaimer statement. During today's call, we will be making forward-looking statements, including, without limitation, statements with respect to our future stock performance, plans, opportunities, and expectations with respect to financing activities and the execution of our business plan. These statements must be considered in conjunction with the disclosures and cautionary warnings that appear in our SEC filings. Investors are cautioned that all forward-looking statements made on this call involve risks and uncertainties and that future events may differ materially from the statements made. For additional information, please refer to the Company's Securities and Exchange Commission filings, which are posted on our website and are available from the Company without charge. Our discussion on the call today will include a review of non-GAAP measures as a supplement to financial results based on GAAP because we believe these non-GAAP measures serve as a proxy for the Company's sources or uses of cash during the periods presented. A reconciliation of non-GAAP measures to the most directly comparable GAAP measures is included in our earnings release for the three and nine months ended September 30, 2023 which is available on our website. Adjusted EBITDA is defined as net income or loss plus to the extent deducted in calculating such net income, interest expense, loss on extinguishment, loss on lease termination, USDA cash grants, income tax expense, intangible and other amortization expense, accretion expense, depreciation expense, gain on litigation and share-based compensation, plus income tax benefit. Let's review the financial results for the third quarter of 2023. Revenue during the third quarter of 2023 decreased 4% to $68.7 million compared to $71.8 million for the third quarter of 2022. Our India Biodiesel operation experienced an increase of 121% in production by delivering 15,500 metric tons of biodiesel during the quarter of 2023, compared to 7,000 metric tons during the third quarter of 2022. Our California ethanol operation saw a decrease in the volume of ethanol sold from 15.7 million gallons in the third quarter of 2022 to 13.8 million gallons in the third quarter of 2023. Delivered corn price improved from an average price of $9.59 per bushel during the third quarter of 2022 to $7.48 per bushel during the third quarter of 2023. Gross profit for the third quarter of 2023 was $492,000 compared to a gross loss of $1.1 million during the third quarter of 2022. Our Indian Biodiesel segment provided $2.8 million of this gross income. Selling, general, and administrative expenses were $9 million during the third quarter of 2023 compared to $6.4 million during the third quarter of 2022 due to our continued investment in our ultra-low carbon initiatives along with non-cash charges for stock compensation. Operating loss was $8.5 million for the third quarter of 2023 compared to an operating loss of $7.6 million for the third quarter of 2022. Interest expense during the third quarter of 2023 was $10.2 million excluding accretion and other expenses in connection with Series A preferred units in our Aemetis Biogas LLC subsidiary compared to $7.1 million during the third quarter of 2022. Additionally, our Aemetis Biogas LLC subsidiary recognized $7.7 million accretion and other expenses in connection with preference payments on its Series A preferred units during the third quarter of 2023 compared to $2.8 million during the third quarter of 2022, along with a loss on extinguishment on Series A preferred units of an estimated $49.9 million during the third quarter of 2022, as a result of a charge related to the redemption of Series A preferred units as part of the amendment to the preferred unit purchase agreement. Net income was $30.7 million for the third quarter of 2023 compared to a loss of $66.8 million for the third quarter of 2022, driven primarily by tax credit sales of $55.2 million during the third quarter of 2023, along with the one-time unitholder redemption charge of $49.4 million during the third quarter of 2022. Cash at the end of the third quarter 2023 was $3.9 million, compared to $4.3 million at the close of the fourth quarter of 2022. Investments in capital projects of $8.8 million were made during the third quarter of 2023, further highlighting our commitment to building ultra-low carbon projects. Now, I'd like to introduce the Founder, Chairman, and Chief Executive Officer of Aemetis, Eric McAfee for a business update. Eric?

Thank you, Todd. Aemetis is focused on producing below-zero carbon intensity products that reduce air pollution and carbon emissions to improve the environment while providing health and economic benefits to local communities. We are pleased to report that Aemetis has achieved the milestones enabling the transition to positive cash flow from our three operating businesses in California and India. During the third quarter, we completed key milestones also in our two development businesses. In September, we received approval of the Use Permit and CEQA for the development of the Sustained Aviation Fuel Plant, and we made progress on project development after receiving the construction permit from the State of California for the CO2 sequestration characterization well. And we generated a profit of $30.7 million in the third quarter, and we paid down $50.2 million of high-interest-rate debt in October. We are growing and diversifying our existing dairy, renewable natural gas, and ethanol businesses in California and expanding our biodiesel and tallow feedstock businesses in India by adding facilities to convert our biofuels and byproducts into sustainable aviation fuel, renewable diesel, and renewable hydrogen. To further reduce the carbon intensity of our products, an important business that we are developing is the sequestration of CO2 produced by our renewable fuel facilities. Each of these businesses reduces air pollution and carbon emissions while generating valuable federal tax and renewable fuel standard credits California low carbon fuel standard credits and carbon credits that are needed by the energy industry, corporations, and companies seeking to decarbonize their operations or to offset their carbon emissions. We are executing on a plan to grow to $2 billion of annual revenues and more than $600 million of annual positive cash flow. We invite investors to review the Company presentation on the homepage of the Aemetis website and our press releases to see the steady progress being made on delivering our plan. The Aemetis Biogas business has multiple revenue sources, including renewable natural gas fuel, California low carbon fuel standard credits needed by oil companies to offset carbon emissions from the sale of petroleum fuels in California, federal renewable fuel standard credits required by oil companies under federal law, Inflation Reduction Act investment tax credits, and Inflation Reduction Act production tax credits that begin in January 2025. An example of the types of credits that we generate from our low carbon projects is the sale of $63 million of federal tax credits in late Q3 to a corporate purchaser for $55 million in cash. These credits were generated from Aemetis investments and qualified biogas assets under Section 48 of the Inflation Reduction Act, which provides about $400 billion of federal tax credits to projects such as ours that achieved the goals of new jobs, new investment, and the decarbonization of energy. This IRA tax credit sale required extensive third-party review and oversight, including a cost segregation consulting firm that issued a verification document, a national law firm that issued a tax memorandum setting forth the calculation of the IRA tax credits, a leading insurance brokerage firm, a group of insurance companies that provided a tax credit insurance policy, and a highly profitable corporate buyer that purchased the federal tax credits at a discount. We expect to continue to generate IRA investment tax credits in the Aemetis Biogas business at the rate of about 40% for eligible project costs, creating more than $100 million of future cash from the sale of IRA investment tax credits related to the investment and production of renewable natural gas. Beginning in about a year, in January 2025, we plan to generate IRA production tax credits from the production of renewable natural gas. The calculation of the valuation of IRA production tax credits for dairy renewable natural gas under Section 45Z is based upon our expected negative 370 carbon intensity of dairy renewable natural gas. After selling at discount to a purchaser and tax credit insurance costs, the net proceeds to Aemetis are expected to be approximately $60 per MMBtu of renewable natural gas. The Aemetis supplies about 80 dairies and approximately 100,000 dairy cows with wet distillers grain animal feed produced by our ethanol plant. Aemetis plans to generate 1.6 million MMBtus per year from only about 60 dairies. As a result, Aemetis plans to grow cash received from the sale of IRA production tax credits from our Aemetis Biogas business to more than $100 million per year, in addition to generating an estimated $120 million of investment tax credits from the construction of the qualified biogas assets over the next few years. Let's review our five businesses. In the India Biodiesel business, $20.1 million of biodiesel contracts were fulfilled by Aemetis, principally for the three India government oil marketing companies during the third quarter of 2023, generating $2.7 million of positive adjusted EBITDA during the third quarter. We recently announced a $150 million one-year allocation for biodiesel from the three oil marketing companies under a cost-plus contract structure. We started deliveries under this contract in October. The positive impact of cost-plus pricing that is now being used by the OMCs to purchase biodiesel is expected to continue for the next year. The India Biodiesel is debt-free and now generally funds its own operations without outside working capital financing. Our India plant was expanded to 60 million gallons per year of capacity during the third quarter. We continue to expand the production capacity of biodiesel using an enzymatic process, a technology developed by Aemetis at our India plant that allows lower-cost, lower-grade feedstocks to be used to produce high-quality biodiesel. Aemetis believes it is the largest capacity producer in the world using Novozymes enzymes to convert low-cost feedstocks into biodiesel. Due to our process technology advantage, the total capital cost of our expansion to 60 million gallons per year was less than $1 million and was funded entirely by our operating profits in India. To meet rapidly expanding demand from biodiesel by the government-owned oil marketing companies, we are continuing to expand production capacity in India with a plan of 100 million gallons per year of capacity in 2025. The India market is about 25 billion gallons of petroleum diesel, and the government has set a goal of a 5% blend of biodiesel. We expect the cost-plus contracts from India government oil refineries will support the addition of a significant amount of new biodiesel production capacity in India over the next five years, with Aemetis continuing to expand capacity beyond 100 million gallons to supply the increasing demand for renewable fuels. The plant's export of refined tallow from the India facility to renewable diesel producers in the U.S. is making steady progress, with feedstock sales to several biorefinery customers in active discussions. In Aemetis Biogas business, this summer we closed the second $25 million USDA guaranteed loan to build dairy biogas digesters for an additional eight dairies. This closing brought our total to $50 million of committed USDA REAP based project financing known as Renewable Energy for America Program to build 15 fully funded dairies that are designed to produce a combined 400,000 MMBtus of renewable natural gas each year. The third $25 million USDA guaranteed loan should be closed by the end of the year, subject to potential delays from a government shutdown. The fourth through eighth loans are in various steps of the process. When closed, these five additional rounds of financing under the Renewable Energy for America Program are scheduled to provide an additional $125 million in 20-year project financing for the construction of Aemetis Biogas assets. We now have seven fully operating dairy digesters, and are currently constructing additional digesters for 10 dairies. These dairy digesters are expected to generate approximately 400,000 MMBtus per year of renewable natural gas. We expect to have nine digesters operational by the end of 2023 and plan to speed up the rate of digester development in 2024 as we close financing from Aemetis Biogas 3, 4, and 5 for $75 million of new financing. A few months ago, we received our default negative 150 carbon intensity pathway approval for six dairies to generate low carbon fuel standard credits. And we expect more approvals in the next few weeks. While we await the approvals of our provisional LCFS pathways for credit generation in California, we store the renewable natural gas underground and carry the RNG as inventory until required to deliver to customers. Aemetis and other RNG producers have experienced significant delays in the California Air Resources Board approval process, with some at 24 months and counting. We expect CARB to address this delay and the upcoming reauthorization of the LCFS program in 2024. We noted earlier this year that the dairy digesters were performing above expectations. Our updated plan that we expect to release in Q1 2024 will include updated volumes based upon the successful production rates of the biogas digesters during 2023. We are pleased to have passed the operational startup phase and are now positive cash flow from operations at Aemetis Biogas. We are selling Federal D3 Renewable Identification Numbers at a price that is about 75% higher than a few months ago, as the price of D3 RIN has increased to $3.50 per RIN compared to $2 per RIN in June of this year. The EPA mandate for D3 RINs for the next two years significantly exceeds the expected production from biogas projects, so oil companies are competing to purchase D3 RINs, driving up the price. Though we plan to continue to utilize long-term USDA guaranteed REAP loans for the construction and operation of Aemetis Biogas projects, we recently paid $30 million to Third Eye Capital pursuant to their financing of the biogas project. Additionally, the original financing was extended to the end of December for $3 million after which any remaining balance is converted into a simplified promissory note at about an 8% lower interest rate than the prior conversion promissory note. In the Aemetis sustainable aviation fuel and renewable diesel business, we received approval for the primary permit for the construction of the 90 million gallon per year SAF and RD plant at the Riverbank site. The Use Permit and California Environmental Quality Act approval, allowing the use of the 24-acre site for a sustainable aviation fuel and renewable diesel plant was approved on September 12th. The authority to construct air permit is expected to be approved in early Q1, 2024. We have signed $3.8 billion of supply contracts with 10 airlines and a $3.2 billion renewable diesel supply contract with the National Travel Stop Company. We are now obtaining the final permits for the development of the plant, and due to market conditions, we expect to revise these agreements to reflect updated project timing and terms in 2024. The HEPA process or SAF production is currently less expensive than the Ethanol to Jet process when considering the current price of Ethanol and the yields of current production technologies. Aemetis is deploying the Topsoe HydroFlex process that enables the production of sustainable aviation fuel and renewable diesel at any output ratio, thereby allowing the maximization of pricing by the production and sale of the higher value fuel. The need for sustainable aviation fuel continues to increase, but the overall market supply of SAFs continues to be delayed, resulting in significant supply shortages that are expected to continue for the foreseeable future as the 90 billion gallon per year aviation fuel industry seeks to reduce air pollution and carbon emissions using renewable fuel to replace petroleum jet fuel. Truck engines are primarily powered by petroleum diesel, so renewable diesel is a drop-in replacement fuel that does not require any capital expenditure by the truck operator, unlike hydrogen or battery electric trucks. However, renewable natural gas engines allow trucks to generate significantly lower emissions and enjoy approximately 50% or more savings on fuel costs due to the number of credits generated by carbon-negative dairy renewable natural gas. The California Air Resources Board has stated renewable natural gas is an important source of renewable hydrogen for future truck engines, allowing the trucks to be zero emission using a carbon-negative fuel. We believe that Aemetis is very well positioned to supply renewable natural gas, hydrogen, and below-zero carbon electricity to the future for trucks and cars in California, enabling the transition to zero-emission and below-zero carbon intensity heavy-duty and light-duty vehicles. For the Aemetis ethanol business, during Q1 and most of Q2 of this year, we completed an extended maintenance and upgrade cycle for our Keyes ethanol plant, which helped us avoid significant losses during the quarter due to extraordinarily high natural gas prices early this year. Equally important, this pause in production helped us avoid future plant shutdowns that would have been required to install key components of our energy efficiency upgrades. The result was an acceleration of our planned projects to reduce our biofuels carbon intensity through a number of plant efficiency and electrification projects. We also accelerated the installation of an entirely new Allen Bradley Distributed Control System with artificial intelligence capabilities, along with several other important process upgrades. We restarted the Keyes ethanol plant in late May and ramped up production during June and July. The plant generated revenues of $47.4 million during the third quarter and has been running well with the new systems installed and long-term maintenance projects completed. The goal of our Keyes ethanol plant upgrades is to significantly reduce the use of fossil-based natural gas at the plant. When these projects are completed in 2024, we expect that natural gas usage at the Keyes ethanol plant production facility will be reduced by more than 80%. This transformation from fossil fuel natural gas to renewable electricity will put Aemetis at the forefront of decarbonized manufacturing facilities in California and is expected to reduce the carbon intensity of fuel ethanol produced at the Keyes plant by double digits. In the next few months, we will be completing the installation of a $10 million solar microgrid with battery backup that will increase the use of renewable electricity at the plant. Our mechanical vapor recompression unit has now completed Process Engineering Design and has begun equipment fabrication for installation late next year. These upgrades as well as the replacement or upgrading of various heat exchangers and process equipment, and the installation of the new AI-enabled decision control system is designed to allow Aemetis to achieve meaningful energy cost savings and increase our revenue through the sale of lower carbon intensity fuel ethanol. In summary despite facing some temporary and highly unusual external headwinds in the first and second quarter of this year in our ethanol business, operational performance and project milestones for the Aemetis Biogas and ethanol plant businesses continue to be on track with the Company plant. In the Aemetis carbon capture and sequestration business, we were awarded the first CO2 sequestration characterization well permit issued by the state of California to a non-governmental project in May. The CO2 characterization well is designed to provide geologic data for the EPA Class 6 injection well planned for the Riverbank site. The recent $5 billion acquisition of Denbury by Exxon is an example of the timeliness and relevance of CO2 sequestration to oil refiners and other CO2 emitters. In California, Senate Bill 905 established a public engagement process to resolve specific issues related to CO2 sequestration projects, including royalty rates and the unitization of pore space rights. We continue to focus on the development of the project, but we are supported by the legislative and political process in California that is implementing the regulations for the capture of CO2 to achieve carbon emission reduction targets set by Governor Newsom in a letter to the California Air Resources Board last year. The California Air Resources Board has held several low carbon fuel standard public events where staff stated the CARB plans to significantly increase the number of credits required under the program by significantly expanding LCFS mandates. CARB's own model estimates that the increased mandates will raise the price of LCFS credits to more than $2.20 per credit in the next two years. We expect that LCFS credit prices will begin to increase after the January 2024 CARB Board approval of the revised regulations that are expected to implement an automatic ratchet mechanism and a one-time increase in the number of LCFS credits to reduce the inventory of credits. LCFS credits generate revenues for Aemetis in all of our U.S. businesses and indirectly benefit our India business that can produce feedstock for U.S. renewable diesel and sustainable aviation fueled biorefineries. Currently, Aemetis captures 150,000 metric tons per year of CO2 emissions from our Keyes Ethanol plant and reuses the CO2 for local customers. This reuse of CO2 can generate 45Q transferable tax credits under the Inflation Reduction Act. In Phase 1 of the Aemetis Carbon Capture project, we plan to inject up to 400,000 metric tons per year of CO2 emissions from our biogas, ethanol, and jet diesel plants into two sequestration wells that we plan to drill near our two biofuels plant sites in California. We expect to construct two CO2 injection wells that each have a minimum of 1 million metric tons per year of injection capacity, with additional CO2 supplied by other emission sources to sequester a planned total of 2 million metric tons per year of CO2. The planned 2 million metric tons of CO2 per year sequestered by the Aemetis Carbon Capture project are expected to generate an expected $170 million per year from Federal Direct Pay Tax Credits or about $85 per metric ton of CO2, as well as an estimated $400 million per year at a projected $200 per ton of sequestered CO2 from the low carbon fuel standards. We believe the fixed amount of $850 million provided by the direct pay funding over the first 5 years of project operation should support funding the estimated $250 million capital cost of the two injection wells and related equipment. In summary, all of the five Aemetis businesses are synergistic and create what we refer to as a circular bioeconomy within Aemetis. We use the biofuels, byproducts, and waste products from our facilities and local areas as feedstock to produce low and negative carbon intensity renewable fuels to meet government mandates for air quality improvement and carbon emissions reductions. The strong demand for dairy renewable natural gas and the rapidly growing sustainable aviation fuel market are key areas of investment and project development at Aemetis. Our existing facilities are focused on projects that improve energy efficiency, reduce carbon intensity to increase revenues at lower costs and technologies enabling the use of lower-cost feedstocks at our existing production facilities. Our company's values include a long-term commitment to building value for shareholders, the empowerment of and respect for our employees and business partners, and making significant and positive contributions to the communities we serve. Now, let's take a few questions from our call participants. Ali?

Our first question is from Manav Gupta with UBS.

So the first question would be on the CARB staff proposal. We believe you also played a very key role in getting across the line, looks like it is a very positive program, with a 50% increase in compliance by 2030 and then obviously the ratchet mechanism, which pulls the program forward. What the bears are saying here is that given where the levels are currently and given that we would continue to build probably until 2024 end. That carbon prices may or may not move even into late 2024 or early 2025. And you obviously on the call said, you expect an earlier movement. So, first of all, can you comment a little bit more on the program, what you liked and then why do you believe that the carbon prices would actually start moving in 2024 versus 2025?

I think that the traders that work for major oil companies are very smart people. And what they're looking for is certainty, not just for a month or for a quarter. They're actually, like we are, investing in long-term capital projects that have an impact on carbon intensity, and they know that if they can't cover their obligations related to those projects, that there are significant compliance costs that frankly have to be considered in their operations over a long period of time. And so, having spent a lot of time with those traders, unfortunately, what they see right now with CARB is a lot of political confusion between environmental groups and other voices and what the CARB staff is proposing, and so they've taken a wait-and-see attitude. The CARB staff is expected to present to the board in January 2024, and the board has stated that they intend to approve the implementation to be effective in the second quarter. I think that kind of certainty is going to immediately allow people to calculate what they each entity will require in future LCFS credit mandates, and if the automatic ratchet mechanism is written the way that they've proposed, it's going to be very clear: the more LCFS credits generated, the more rapidly the automatic ratchet mechanism will move you to for additional compliance; it will move forward one year. For example, in year 2030, it drops very significantly between 2030 and 2031. So though the ratchet mechanism doesn't have to wait until 2030, I think that the calculations could easily indicate that the 1st ratchet might be as early as 2026. So as people game out how many LCFS credits they're going to need, they're going to conclude exactly what CARB put on Slide 51 of their February 2023 webinar, which was under any scenario of the ratchet mechanism plus the one-time step down. There will not be enough LCFS credits presented by renewable diesel and SAF, et cetera, coming to the market. Once you conclude that, then you need to conclude that you're going to buy as much as you can to minimize your future compliance liability because the price is going to be triple what it is today. So what I just said took me a lot longer than it will take for a trader to conclude this, they will say just buy what you can, and let's see how fast the price moves. And once you get that momentum, I don't think it's going to take 1.5 years for the market to say we just need to get to the cap, and we need to be there as fast as possible because we need to cover our future liabilities. As the price moves up, you're going to see a kind of panic among the folks that are late to the party as they see their compliance costs dramatically increase. Of course, that panic will drive further buying. The good news is there's already a built-in cap; there's a built-in mechanism to make sure the market doesn't get overheated in terms of price. It will not go to $300 or $400; it will stop at a cap. And, we saw we were very close to the cap in August 2020. The reality is we probably will be there again in 2024. I wouldn't be surprised at all if these traders, very quickly move the price once certainty is in place.

Thank you, guys. Let's hope that plays out exactly as you said. My quick second follow-up is moving from California to federal level. We still haven't got the full guidance on 45z, but for a company like you where the RNG carbon intensity can drop closer to like, 375, 400, like if they don't cap it, does that mean you could make $7 or $8 a gallon in 45Z credits on top of what you make on LCFS for your RNG projects and even you're looking to target sap of zero carbon intensity, that's like a $1 a gallon? Does that math sound right, sir?

It does. Each one of our businesses has different carbon intensity. Renewable natural gas is going to be the big winner, not just for us, but any dairy renewable natural gas producer under the Placement Reduction Act 45Z section is going to be able to, in our case, be about $68 per MMBtu. Each MMBtu is 7.2 diesel gallon equivalents. So, if you take $68 divided by 7.2, obviously, that's a very attractive amount per diesel gallon equivalent, but it's based upon having a negative 370 carbon intensity, which you're not going to achieve with renewable diesel or other fuels anytime soon. The big winner in the 45Z is dairy renewable natural gas, and landfill renewable natural gas. The numbers I've seen are positive 30; we're at negative 370. They're positive 30. So yes, they're going to generate 45Z, but probably at one-fifth the rate of what we're doing. The calculation of 45Z is by the way done by the same people that we just closed this $55 million cash proceeds from tax credit sale. It's the same team, the same lawyers, the same accountants. It's frankly the same legislative process that they're dealing with the Inflation Reduction Act. So, this is not something brand new. This is something we've been working on for more than a year. We are fairly comfortable that this has been thoroughly vetted by a wide number of our advisors, and they'll come up with roughly the same calculation. So, we are expecting after a discount for sale about $60 per MMBtu, it would be the net proceeds to have.

Our next question is coming from Derrick Whitfield with Stifel.

Eric, I wanted to start with the refinancing of your preferred. If I heard correctly in your prepared remarks, it will be converted to a promissory note at year-end at a rate that's 8% lower than present. Could you confirm that that's correct and also the absolute level of the principal amount and interest rate?

Sure. The refinancing of the biogas preferred is structurally an extension, which is what we did December last year, May of this year, and now August of this year. So this is the third extension of the existing financing. The extension, which includes the months of September, October, November, December—four months—is an additional increase of $3 million. So the $135 million will be $138 million, but we just paid $30 million down. Therefore, it will be $108 million will be the balance at the end of December. We have additional payments expected under this program over time. So, after December, it’s currently papered to convert into a promissory note that's got a floor price of about 16%. The prior note was 24%. So it's about an 8% interest rate. It's one-third lower interest rate than what it was in the prior terms of the prior extension we did in May. If we extend again, we would then probably do exactly what we did here, which is just increase the amounts in a certain amount. But it is papered to automatically convert, so in the absence of us agreeing with Third Eye to extend, then it would just automatically convert into this interest-bearing note in the amount of $108 million at the end of the quarter. We do have a number of counterparties we're working on right now that would substantially change this with a substantial pay down and some other things. So, there is ongoing discussion and due diligence and negotiation that would reduce that $108 very significantly.

And for my follow-up, I wanted to confirm a couple of points from your prepared remarks on dairy RNG. First, I think you heard, I think I heard you say a new CI score of 370, negative 370. Is that due to RNG volume over performance? And then secondly, regarding the non-projects that are online by year-end, could you comment, I think there's a slight delay with some of the projects you were expecting to come on? Just maybe comment on the source of those delays.

Yes, actually, you were exactly right. The increased volume of biogas production and the way that it impacts our CI score caused our CI score to decrease from roughly 415 to 370. It just frankly reflects that there's only a certain amount of carbon intensity reduction per cow. So, our process is producing more biogas molecules than expected, meaning that the overall carbon intensity per molecule is slightly less. The overall economics, by the way, are pretty much unchanged from the perspective of the number of credits you get. But we do get more revenues and more D3 RINs, and the D3 RINs having increased from $2 to $3.50 means that more D3 RINs is a very, very good thing. The reason for timing is largely our USDA loan process. We are very committed to getting better and better at applying for Renewable Energy for America programs, lining up all the consultants, all the advisors, all the permitting, everything that is involved with them, giving us a commitment letter and then executing on the loan. The first one took 20 months; the second one is roughly eight months. We expect to be able to execute on these in a five to six months time schedule on a go-forward basis. There's education involved, there are new staff members at USDA that need to be educated, and we are committed to doing it right because we end up with 80% of the loan guaranteed by the U.S. taxpayer. More important than the interest rate, yes, it's true, the interest rate is lower than the market, but far more important is a 20-year amortization of the loan that is not available in the bond market, the commercial lending market, the tax-free or taxable municipal market, or any other market you can find. There is not a 20-year loan available for biofuels projects, other than a U.S. guaranteed transaction in this particular environment. So, we are very pleased with our USDA relationship and intend to continue to commit ourselves to supporting that relationship and executing on the business model. They similarly have the goal of doing this quicker and more efficiently.

Our next question is coming from Amit Dayal with H. C. Wainwright.

So Eric, if you don't mind, can we go over some of the biogas numbers you provided in your commentary? So you're saying you'll be at nine digesters at the end of 2023. How many should we expect by the end of 2024? And then how does that number play alongside your comments about generating over $120 million in PTC, $100 million in ITC in 2025, I believe?

Yes, the $120 million of investment tax credits is actually over the course of the build-out of the project. The updated plan which we'll put out in Q1 will show you what than actual impact of that is on a quarterly basis. The average number of MMBTUs per dairy is about 25,000 per dairy. What's happening is we're getting much bigger dairies, and we're actually getting dairies that are consolidating with Dairies Next Door. We're finding that the language of one dairy equals 25,000 MMBTUs is not reflecting accurately what's going on in the field. So, we're going to be transitioning this language to talking about how many cows we're going to be processing the waste from. That will much more accurately reflect what is for people's calculation purposes. So when we say we're adding another 10,000 cows, you'll be able to then say, oh, by the way, that means X number of MMBTU. So between this call and the next call and certainly in the five-year plan, you're going to see a transition to what's called wet cow equivalents. So different kinds of cows, you get to in the industry, all calculated by one simple number, the WCE, and then the number of MMBTUs per year, and then it's very easy math for everybody. So, the answer is in 2024, we have some very, very large digesters. I think some of the industry's largest digesters are being built by Aemetis right now, which takes multiple dairies of waste. In a very efficient process, we have one that's four dairies. We're building one large digester, but we're bringing four dairies online all at the same time. So the pace of dairy development is very rapid in 2024. Digester development is larger digesters in several cases. And so, I think the language we're going to start changing to is just how many cows and that will make it much, much easier for everybody to think about and calculate it. So we'll be coming out with those numbers, certainly in the first quarter in our updated plan. You'll be seeing it in press releases. We'll probably do a year-end wrap-up press release on some of the achievements of the year in Aemetis and talk about using these wet cow equivalent calculations. So, let me hold back until we put those things on paper, because we're rapidly accelerating the program. As we are expected to close the third $25 million funding from the USDA and have 4th, 5th, 6th, and 7th all in process, those are all feeding into the pace of 2024.

We'll keep an eye out for it, and then in relation to the monetization from the IRA for the biogas credits. Is this going to be lumpy in the future, Eric? Or going forward, will this be a more sort of quarterly number that will show up in the financials?

It's a very good question. It's actually, I would say, the core question about the valuation of the Company today. Our particular customer in this situation is a company that really would prefer $50 million or more for a transaction. They have a very large tax liability on a monthly basis. We transacted this in a very efficient way, aggregating them all together and doing one transaction for $63 million in tax credits. We do not expect to be transacting quarterly until 2025, roughly a year from now. The reason why is because these investment tax credits are spread out over a longer period of time; they are not $50 million a quarter's worth of numbers. So, I would expect over the next year to probably see two transactions; my projection would be the first one probably in the second quarter and the next one probably in the fourth quarter. We've largely are going to time those transactions based upon just the aggregate volume. So we'll not be every quarter for the four quarters of 2024. But when we get to 2025, every single quarter, we will want to monetize. I think I talked about the volumes; you're talking about in excess of $15 million per quarter from the production tax credits and the investment tax credits together in our various businesses in the first quarter and thereafter in 2025. So, we have stated publicly it's a total of about $800 million coming into the Company. And so other than 2024, it does end up being a bit of a quarterly after-tax benefit and cash benefit to the Company, and just it's going to be lumpy in 2024.

Okay. Thank you for that.

Amit, let me mention to you, the way that the production tax credits are represented is, they're another source of revenue. Just like low carbon fuel standard credits are revenue and the federal D3 RINs revenue and the molecules revenue. The production tax credits will not be shown on our income statement the way that our investment tax credits are. They will show up just like revenue. So, every quarter revenue is higher, they're an after-tax benefit, so earnings is higher, EBITDA is higher. It will just be like an LCFS, RFS or even a molecule sale; it's a source of revenue. The investment tax credits show up as another income; it's a tax benefit is what it shows up as. Though we get in cash, most people don't think about taxes as being cash that comes to you. It's cash on our balance sheet, but it shows up in our P&L, below of operating income. This does, of course, as we know, show up as after-tax income, so our earnings per share goes up, but it doesn't come into EBITDA as investment tax credit does not come into EBITDA. It comes into cash and it goes into earnings. And that's confusing to many investors I know, but that's what it is. It's like EBITDA plus cash because most people don't think of tax as actually creating any cash; in this case, it does.

Yes, I guess folks will have to start looking at the cash flow profile from a valuation standpoint going forward on this?

Yes. Well, I think when we get the production tax credits, it's going to be very easy because they won't have to do much calculating; it'll just be in revenue, it'll be in earnings, it'll be in operating income. It's going to be very easy. It's primarily this $120 million of future investment tax credits. And we do have some other things we're doing that we expect to generate investment tax credits. I think that's where people are going to be confused. We got the cash, but it's not revenue, right? We got the cash, but it's not an EBITDA. So what is it? Well, it's people are going to be confused about that part of the business. It's just something that we're going to have to deal with. You know what it really is, it's this reduction of high-interest trade debt. That's $120 million more of reduction in high-interest rate debt; that's one clean way to think about it is that your earnings go up because your debt goes down.

Right. No, I get it. And we saw that in the financial testing already.

Yes, we paid $50.2 million of debt on this one.

Yes. On the India Biodiesel capacity ramp to 200 million. How much investment is needed? And will the cash flows from that operation basically fund that expansion?

It's a good question. It is going to be funded from India. We do have cash flow, certainly, under this cost-plus contract that will largely fund all the activities needed to do it. We will probably incur a small amount of debt near the end of the year, but that will be paid off in 2025. So, the reality is it's just going to all be paid by cash flow in India.

And then how does that set you up, so you previously said you might monetize that asset in some fashion. So now that the facility is operating sort of more regular fashion. Are you considering some of those options you had previously highlighted?

We are currently hiring at the executive levels in India, so we will be well prepared in 2024 for what I believe is going to be an attractive public market opportunity. The real question for us is whether the Sensex in India is the right market. I personally strongly prefer the Sensex. The structure for companies going public is very, very favorable. So if for some reason that does not appear to be as attractive for whatever market conditions, there are a number of opportunities we have, including, obviously, NASDAQ, but we have other exchanges that are excited about India, and certainly, there are other places we could do a public offering.

Our next question is coming from Matthew Blair with TPH.

If you could talk a little bit more about the California Ethanol segment? What was EBITDA for that segment in the quarter? It looks like your realized ethanol pricing might have been a little bit softer than expected. Could you talk about the drivers there? And then you've poured a fair amount of investment into this plant. Are some of these projects up and running? Or is it really 2024 when we'd expect to see the upside from things like the ZEBREX plant and the solar grid and those sorts of investments?

Let's talk projects first and then we'll revert back to EBITDA. The decarbonization of this ethanol plant is a new idea for many folks unless you're getting a low carbon fuel standard credit, which means you're building your product in California, pretty much 100% of your product, you don't really get paid for it. Many plants benefit from coal-fired electricity, for example, just really cheap and many plants were built specifically because they have access to cheap coal-fired kind of double electricity. Our projects move us to renewable electricity; we have a $10 million solar project, which is literally doing the cutovers here in the next couple of weeks. We got the tuning process, so we'll be fully operational in a month and be doing the final adjustments; we’re looking for an early first quarter full operation of that unit. We got an $8 million grant from the California Energy Commission to do that decarbonization. But in order to fully utilize that renewable electricity, we need to have systems in the plant that do not run on petroleum natural gas. So, the mechanical vapor recompression concept, which is widely used in the industry, specifically in the dairy industry, at creameries, recompresses your steam by using large electric fans like the power plants to force the air into higher pressure, which increases its temperature. Recompressing using electricity means that we can significantly reduce literally by 80% our petroleum natural gas use, which comes from very carbon-intensive energy sources. That decarbonization will not be fully in place until we have implemented our MVR, which is currently structured to be at the end of 2024. So, we're upgrading the energy sources. That's solar, that's online literally next month and tweaked and fully sold acceptance for Q1. And then we want to use that renewable electricity to change the physical processes in the plant with mechanical vapor recompression. The MVR economics generate in excess of $1 million a month of improved margin by saving us today about $800,000 a month in natural gas and then through lower carbon ethanol, generating almost an equivalent amount of increased ethanol value. So after the increased cost of electricity is subtracted, it's a $15 million per year increase in cash flow at the ethanol plant. We have some other things that are smaller, the artificial intelligence system and some other things that are just optimizing what we're doing. So our overall initiative here, though, is to reduce costs, increase revenue, and in so doing, be able to pretty consistently generate $2 million a month even if all of our competitors are breaking even; we're still making $2 million a month.

And do you have the EBITDA for that segment in the quarter?

It was approximately breakeven. This marked the conclusion of our startup phase, although we achieved positive cash flow on a monthly basis towards the end of the quarter. We were still in the startup phase at the beginning of the quarter.

And then my follow-up is on, you mentioned the LCFS pathway delays that you're experiencing. I just wanted to see, is that something that's unique to the complexity in low CI of dairy RNG? Or is that something that's affecting everyone across the board? And is your best guess now that you'd receive that pathway by Q2 '24, and that's when you start to show EBITDA for the dairy RNG segment?

There are Tier 1 and Tier 2 pathways, one of which is a relatively formulaic and quick, for example, an ethanol plant decarbonizing calculation that might take three to four months for that pathway to be approved because it's fairly standard and is changing a couple of the elements. The biogas industry in general is all stacked on a pile of more than 50 projects, according to what we've been told by CARB staff. Many of those projects have developers that are not very familiar with this process and require a lot of handholding by CARB staff. That has been their explanations for why there's been such a long delay in getting approvals. Unfortunately, the current process does not allow more experienced developers such as us—we're the largest LCFS ethanol producer in the history of California at our plant. Our experience and our know-how are not giving us any benefit; we're literally in a pile with a bunch of people that may have never done this in their entire life. Our problem is that we're waiting for CARB to fix this in the next go-around, A very easy fix. It’s just change your default pathway to negative 350. So during this time period, which we're waiting, where we're already generating these local fuel standard credits, we generate them at the rate that's more accurate. Currently, their negative 150 default rate is just not accurate; it's just wrong. I've got public statements; you want to Google Andy Foster or Eric McAfee. You're going to find that we are very active on this topic and interfacing with the top people all the way to the number one top person at CARB on this particular topic. Their general response is, yes, we need to fix it. Yes, it's a good solution. Yes, we need to do something about it. So, in January 2024, we expect that to be an element of what they're doing. They have changed staff management in the program within the last month, so maybe there's going to be some breakthrough just by having some new management. This is an unacceptable underperformance by a regulator that's directly damaging the financing and performance of the entire process of decarbonization; it is absolutely a problem that CARB needs to focus on and it's far past fixing, they should have fixed it two years ago.

Our next question is coming from Dave Storms with Stonegate Capital Market.

Just curious if you could talk a little bit about the pathway to increasing capacity at the biodiesel plant? I know the OMCs do a lot of gatekeeping over there, but just curious as to how you see that playing out over 2024?

Absolutely, we are very fortunate in that, unlike California, which has a very long, long permitting cycle, permitting in India is not really a constraint on our timeframe. It's mostly equivalent fabrication that is the lead time on what we're doing there. Our vendor in this matter is the same vendor we used for the original construction of the plant. Last time I checked, they had over 600 employees in India. They actually fabricate equipment in India. So, the supply chain there is relatively straightforward, and we have an excellent relationship with some of the other fabricators in India. It's largely a matter of us just continuing to invest in this capacity increase. We are committed to the idea that India is largely a debt-free entity. So, as it generates cash, we can use it for capacity increase. When we get to 100 million gallons, it's quite a large business in India. That's a $400 million plus revenue business in India. And at the margins that we get with Enzymatic Biodiesel, which is roughly 10% higher margins than our regular business because of lower cost feedstock, we're going to be very pleased with the outcome of that capacity expansion. So, it's going to be a gradual process. It's a process that we're expecting to mature in 2025 and very possibly might include some other growth initiatives, which we haven't announced yet. But initially, this is just the first step and trying to meet this more than 1 billion gallon gap in India production that the India government is trying to have us be a part of fixing.

And then just a question of a similar nature. Now that you have the permit at Riverbank, can you just talk us through kind of what logistics and timelines look like for next steps, any milestones that we should keep an eye out for going forward?

What’s called the authority to construct the ATC permit that is issued by the air district and that's in process right now. We expect to announce that in early Q1. And then at that point in time, we're just in full completion mode on the project financing. The EPC, the Engineering Procure Construct Agreement, which sets all pricing will be completed to then have the solid financing numbers in place. So that all is happening first quarter, second quarter next year. We have active discussions, literally on a regular basis with equity investors and debt investors. There's a lot of interest in SAF. So, there are a number of peer financial players, there are strategic players, there are technology providers that we already do business with. There are a lot of people who are very, very interested in being direct investors at the entire side, right side of the balance sheet, some of whom are global names everybody would know and others are more strategic interests. We've also mentioned that our 10 airlines that we have contracts with; some of them have created funds to invest in SAF. We have active discussions with those guys, but those discussions are basically lining up for the air permit, the authority to construct, and then the EPC agreement, the actual fully wrapped guaranteed contract with our contractor. We’ve already announced that we intend to use a $2 billion revenue per year company called CTCI, which has experience in renewable diesel plants in California and has proven themselves to be a contractor that's willing to get in there and really work when the going gets tough. We think that it's a great opportunity to work with a proven California contractor in our industry.

Our final question today will be coming from Ed Woo with Ascendiant Capital.

My question is on the Inflation Reduction Act tax credit that you sold. You sold $63 million for $55 million. As you move forward and get more experience selling these, would you be able, do you think you'll be able to lower the discount window? And also I guess, I'm not sure how much time was involved, but to speed up the, I guess, the organizing and completing the sale of these tax credits?

The discount is primarily driven by the non-buyer discount. The buyer discount is only a part of the transaction cost. The insurance policy and other costs in this one transaction were reflective of the first time kind of transaction costs. So, it's roughly a 15% amount all in between $63 million and our net amount that we received. We do expect a tightening as that goes forward. In what timeframe and in what area, I would say I'd be less certain, but I do expect it to be tightening certainly down to 12%, maybe as small as 10%. It's a tax credit, so we could just sit there and use it ourselves and get 100%. At some point in time, we'll just make that determination and we'll not have a discount at all because we'll just apply it to our income tax obligations.

Thank you. There are no further questions at this time. So I would like to turn the floor back over to management for closing comments.

Thank you to the Aemetis shareholders, analysts, and others for joining us today. Please review the Aemetis Company presentation that is posted on the homepage of Aemetis website. We look forward to talking with you about participating in the growth opportunities here at Aemetis.

Thank you for attending today's Aemetis earnings conference call. Please visit the Investors section of the Aemetis website, where we'll post a written version and an audio version of this Aemetis earnings review and business update. Ali?

Thank you. This concludes today's teleconference. You may disconnect your lines at this time, and we thank you for your participation.